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PEH:Well Production Problems

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Publication Information

Vol4POECover.png

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume IV - Production Operations Engineering

Joe Dunn Clegg, Editor

Chapter – Well Production Problems

Raymond Jasinski, SPE, Schlumberger Ltd. (retired)

Pgs. 367-409

ISBN 978-1-55563-118-5
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Introduction


Oil, gas, water, steel, and rock are not always chemically inert under oil/gas production conditions. Their mutual interactions, induced in part by changes in pressure and temperature, can lead to the accumulation of solids, both organic and inorganic (scaling) within the production system, as well as deterioration of the metals that the fluids contact (corrosion).

This chapter discusses these effects in terms of root causes, the operational difficulties resulting, and the principles/methods that have been used to cope. Case histories are not presented in any detail, but references are given to specific papers dealing with cause/effect/cure examples. It is assumed that the reader is not an expert in things chemical but does have a passing acquaintance with the jargon of chemistry and with some of the general principles underlying chemical processes.

"Well production problems" are taken as starting when fluids enter the wellbore and end when fluids reach the storage/treatment facilities. Problems arising from adverse chemistry, occurring in the formation, are discussed elsewhere in the literature. The disposal of toxic coproduction [e.g., H2S, Hg, and naturally occurring radioactive materials (NORM)] is mentioned briefly in this chapter and is discussed in the chapter on facilities in the Facilities and Construction Engineering section of this Handbook. This chapter also does not treat the flow engineering problems, multiple-phase production problems, and the in-situ measurement/control problems attendant to producing hydrocarbons.

Hydrocarbon-Related Problems

Asphaltenes. Certain crude oils deposit solid asphaltenes during production. These deposits may plug the wellbore tubing and valves, as well as coat surface safety and process control equipment.[1] Asphaltenes can accumulate in separators and in pipelines, a problem discussed elsewhere. The tendencies of crudes to deposit asphaltenes do not correlate with the quantity of dissolved asphaltenes present in the reservoir fluid. Some oils with 1% asphaltene or less will form deposits in tubulars, while others with 10% or more asphaltenes will form no deposits. Asphaltenes chemistry varies with field. Asphaltenes contained in oil from a well in the North Sea are chemically different from asphaltenes found in the Venezuela fields, or another North Sea well. The chemistry controlling these depositions is not well defined. Nevertheless, some generalities are possible, which can aid in the design of prevention and remediation technology for a given well.

Asphaltene precipitation as changing pressure and temperature is illustrated in Figs. 9.1 and 9.2. The first figure is a plot of weight percent asphaltene precipitated as a function of pressure at reservoir temperature. A plot of saturation level, rather than percent asphaltene, gives the same form (data obtained from Burke, Hobbs, and Kashoue[2]). The observed general scenario is as follows. There is no asphaltene precipitation on pressure reduction until a critical "onset pressure" is reached—here, nominally 4,500 psi; for the well described in Fig. 9.1, the reservoir pressure is in excess of 5,000 psi. The total amount deposited increases with decreasing pressure, reaching a maximum at nominally the saturation pressure. Asphaltene deposits can then redissolve as pressure falls, at least partially, possibly reaching zero deposition at low pressure ("dissolution pressure"). Not all crudes will show a dissolution pressure at accessible temperatures.


Fig. 9.2 shows an asphaltene deposition envelope (ADE), a plot of such onset pressures (upper boundary) and dissolution pressures (lower boundary) as a function of temperature, overlaid with a saturation pressure/temperature (PT) curve. [3] The sense of the ADE region is that asphaltenes precipitate for PT values between the boundaries. The precipitation problem will be greater the closer the PT values are to the saturation line (as indicated in Fig. 9.1). A possible PT route to avoid asphaltene deposition during production is also shown in the figure.


Pressure and temperature changes are not the only drivers for asphaltene deposition. Combining certain crudes can deposit asphaltenes at the point of mixing (e.g., in the wellbore, flowlines, headers, pipelines, and oil treatment facilities.) Gas lift would favor deposition of asphaltenes from the heavy oil. ADE diagrams can be drawn for such compositional variations as well. [3][4] Shear effects[5] and electrokinetic effects during flow have been claimed as additional mechanisms for asphaltene precipitation. [6] [It is claimed that asphaltenes are electrically charged and the electrical potential generated by flow of these ions through small orifices (similar chemistry to electro-osmosis) can overcome charge stabilization, causing flocculation.] Increases in asphaltene problems with water-production onset are generally observed, as is the decrease in problems with larger water cuts; the definition of "large" varies with field. The presence of other solids with water in the produced fluid can exacerbate the consequences of asphaltene precipitation, generating a greater mass of solids and/or stable emulsions. A rationale for this exacerbation is shown schematically in Fig. 9.3. [7] The surface-active resin/asphaltene aggregates adsorb with wax and other solids onto water droplets, stabilizing an emulsion that can be sufficiently strong to plug production.


Definition of Asphaltenes. Asphaltenes are a compound class, not a single compound, concentrated in the high-temperature distillation residue of petroleum (> 530°C). Other components are heavy oils, resins, and high-molecular-weight waxes. [8] The asphaltene class is defined in accord with the solubility sequence illustrated in Fig. 9.4.


The quantity, and possibly chemistry, of the asphaltene mixture depends on, at least, the final solvent used after the initial separation (e.g., n-pentane vs. n-heptane). (Data are from Mitchell and Speight[9].) An asphaltene mixture using n-C5 as a precipitant will contain more material than an asphaltene mixture using n-C7. Asphaltenes precipitated from a cyclopentane addition would be very small in quantity, compared with those precipitated by n-pentane.

Asphaltene phase separation and deposition in the field generally involve only a portion of the asphaltene fraction generated from the crude oil in the laboratory by n-C5 fractionation (nominally 30 to 50% of the asphaltenes present are precipitated). [10] An example is shown in Fig. 9.5 — a plot of the quantity of asphaltene dissolved (as per n-C5 precipitation) vs. pressure at constant temperature. [11]


The asphaltene mixtures precipitated by either the n-C5 or n-C7 addition are dark brown to black, amorphous solids. The resins tend to be lighter in color and less viscous. [12] Resins have H/C ratios ranging from 1.3 to 1.6; asphaltenes range from 1.0 to 1.3. An asphaltene molecule consists of clusters of condensed aromatic and naphthenic rings. Each cluster contains not more than 5 to 6 rings, connected by paraffin linkages, which may also contain oxygen and sulfur atoms (as sulfides and disulfides). The resins and asphaltenes contain about half the total nitrogen and sulfur in the crude oil. Nitrogen atoms are present predominantly as primary amines and pyridines (bases). It is these nitrogen atoms that can react with stimulation acid, potentially forming sludges. Oxygen is present predominantly in the form of acidic functional groups (carboxylic acids and phenols). These oxygen atoms can form chelants (salts) with iron, potentially forming sludges. Additional compositional details are given in Calemma et al.[13]. An example of an asphaltene molecule is given in Fig. 9.6. [12]


Asphaltene molecules form aggregates with themselves, nominally 35 to 40Å in size, while remaining dissolved in oil. [13] The specific nature of the chemical bonding between the monomer asphaltene molecules within the aggregates has not been well defined, which complicates anticipation (computer simulation) of their deposition tendencies. Various polar interactions are possible in principle, as well as acid-based interactions between the basic nitrogen and acidic carboxyl functions.

The asphaltene molecules and aggregates in a given crude cover a range of molecular weights; [14] the smaller-molecular-weight asphaltenes are the most polar. [12] The difficulties in quantifying asphaltene molecular weight result from the aggregation problem. [8][13] For example, molecular weight ranges of 935 to 16,840 were found for one crude, depending on the instrumental techniques used; others have reported ranges of 1,000 to 2,000,000. [14]

There is ample evidence that resin molecules play a major role in solvating the asphaltenes in oil. Petroleum resins are nominally C30 compounds and are different from nonpetroleum resins, which tend to be a 3- to 5-membered condensed aliphatic ring structure. Fig. 9.7 is a depiction of the structure of two resins derived from a crude oil; the aliphatic side chains are the nonpolar groups; the condensed aromatic rings are the polar groups. [15]


"Common wisdom" is that resins attach themselves to the asphaltene aggregates by polar-group interactions. The nonpolar "tails" of the resin molecules provide compatibility (solvation) with the nonpolar components in crude oil. The concept that resins are the sole solvating oil constituents for the asphaltenes is an oversimplification. Naphthenes precipitate less asphaltenes[9] than the low-carbon-number paraffins (solvate asphaltenes better than paraffins); xylene is used as a solvent for asphaltene removal, which is discussed later. Both classes of compounds (naphthenes and aromatics) are present in oil. The amounts vary depending on the source of the crude.

When this bonding chemistry between asphaltene aggregates and the solvating entities in the crude oil is disrupted, the aggregates come out of solution and flocculate to form larger particles. These flocs are the source of the operational problems. Only after flocculation occurs does deposition occur. [6] The sequence of forms for the asphaltene during oil production is soluble → colloidal particles → flocculated → deposit.

Modeling Asphaltene Deposition. Preventing and/or mitigating asphaltene deposition is facilitated by the availability of the ADE for the particular well. The direct measurement of this stability envelope is difficult, tedious, expensive, and not always possible, particularly with crudes from old exploratory wells. Computer simulations of asphaltene precipitation tendencies are an option, whereby the computer takes "key information" about oil composition and asphaltene properties in order to generate the stability diagram. A problem in establishing a workable model is defining the relevant key information in terms of readily measurable oil and asphaltene parameters. The model is to specify the operating envelope of pressure; temperature under which asphaltenes will and will not deposit; how much asphaltene will deposit; how these parameters vary with liquid composition, particularly in the context of mixing oils from different reservoirs and/or using gas lift to assist production; and how to best remove the asphaltene deposit (e.g., which solvents will be most effective for a particular asphaltene deposit). Not all models available specify all of these items.

There are two broad classes of models for asphaltene dissolution and flocculation, variously labeled as the molecular-thermodynamic approach and thermodynamic-colloidal approach. The scope, limitations, and details of the concepts underlying these model classes are reviewed in a couple of sources.[6][12]

The thermodynamic-colloidal approach holds that the asphaltene micelles are composed of an insoluble aromatic core, onto the surface of which resin molecules adsorb, thereby providing a steric stabilization against their flocculation and precipitation. [6][12] Here, the major focus of the computation is on the resin. The additional solvation, because of other chemical components of the oil, is nevertheless taken into account in the present versions of such simulators. [16]

The molecular-thermodynamic approach[2][12][17][18] envisions that the asphaltenes are monodispersed polymeric entities soluble in the host oil. Conventional polymer theory (e.g., the Flory-Huggins model) has been used to describe the situation. [17][18] The dissolution/deposition process is taken as reversible. The oil is assigned a solvating power (i.e., the resins are not treated as unique entities but as members of the bulk solvent, in which naphthenes and aromatics, for example, are also members).

All models require establishing at least four input parameters (two characteristic of the oil and two characteristic of the asphaltene). One version of the molecular–thermodynamic approach[17][18] uses the molar volume and solubility parameter of the solvent crude oil as a function of pressure, as well as the molecular weight and solubility parameter of the precipitating asphaltene. Correlations with component class analysis (paraffins, aromatics, resins, and asphaltenes), as well as other measured oil parameters, are often used to generate the four input parameters. [16] Model accuracy is improved by calibration to one experimental onset pressure.

Given the uncertainties in asphaltene precipitation chemistry discussed, these computer models should be validated by the operator with comparisons of predicted onset pressures with experimental values for the fields of interest. These models are then best applied to new wells within the field by applying this correlation.

Coping With Asphaltene Deposition. The most effective procedure is configuring the production conditions to stay out of the precipitation envelope established for the well. This involves minimizing pressure drops within the production system—possibly fracturing the formation to minimize drawdown. [19] The use of pressure maintenance by water injection might be appropriate if the field is of sufficient size. [10] If prevention cannot be achieved, it may be possible to move the deposition to a location more easily treated (e.g., at the choke rather than at the perforations).

Chemical inhibitors can be used to prevent asphaltene precipitation. The inhibitors must be placed in the oil before asphaltene precipitation has taken place. In completion systems where capillary ("macaroni") tubing already exists, a continuous injection of an inhibitor can be used. Continuous injection of an inhibitor into pipelined crude is straightforward, as well as the injection of inhibitors immediately before the mixing of asphaltene in incompatible oils. Asphaltene inhibitors can be squeezed into the formation, similar to inorganic-scale inhibitors. However, because of necessity, these inhibitors are oil soluble, resulting in a short functional lifetime for the inhibitor.

Asphaltene inhibitors are generally resinous organic polymers. [20] Their functional groups interact with the asphaltenes in much the same way natural resins keep the asphaltenes dissolved. It is claimed that the strength of the interaction is stronger than with natural resins, keeping the asphaltene dissolved over a broader range of pressure and temperature. Given the variability in the asphaltene structure, it is important that the polymer inhibitor be evaluated on the specific crude in which it will be placed. In principle, it is possible that these polymers could also cause formation damage by altering the wetting properties of the rock. It is obviously prudent to evaluate this possibility on core samples before treatment.

Asphaltene deposits are generally removed manually if present in readily accessible equipment, such as separators and other surface equipment. For tubular and flowline deposits, removal techniques involve chemical methods such as solvent soaks with or without dispersants. Combining solvents and heating may also be effective (see the section on wax removal). Physical methods can be used depending on the hardness of the deposit (e.g., pigging, hydroblasting, and drilling). Pigging (cutting) is appropriate for removing pipeline deposits—often, mixtures of waxes and asphaltenes.

The traditional solvent of choice has been xylene. Two different sources[12][21] describe the use of certain refinery cuts as solvents for asphaltene deposits—mixtures cheaper and more effective than xylene. It is to be expected, given the variability of asphaltene chemistry described, that the refinery-solvent mixture will have to be tailored to the specific well—one mixture will not necessarily cure all. A logic for deriving such mixtures is discussed in Minssieux.[22]

Terpenes (more-expensive natural products) have been used effectively as solvents, replacing xylene because of health, safety, and environment (HSE) considerations. Certain alkylbenzene compounds will stabilize (dissolve or disperse) asphaltenes in simple aliphatic solvents (e.g., heptane). Also, the highly polar and readily available p - ( n -dodecyl) benzenesulfonic acid is a highly effective compound. [23]

The prevention-by-well-design scenario, albeit initially potentially expensive, may be more cost effective throughout the life of the well vs. cleaning/dissolving. As with the removal of inorganic scale, which is discussed later, the costs of the treatments involve not only the chemical itself but the deferred and/or lost oil production attendant to the well's downtime for the treatment. A methodology for asphaltene control in the field, including all aspects previously described, is illustrated in Alf, Betancourt, and Avila.[19]

Waxes

Many crudes contain dissolved waxes that can precipitate and deposit under the appropriate environmental conditions. paraffin wax produced from crude oil consists primarily of long chain, saturated hydrocarbons (linear alkanes/ n-paraffins) with carbon chain lengths of C18 to C75+, having individual melting points from 40 to 70°C. This wax material is referred to as "macrocrystalline wax." Naphthenic hydrocarbons (C18 to C36) also deposit wax, which is referred to as "microcrystalline wax." Macrocrystalline waxes lead to paraffin problems in production and transport operations; microcrystalline waxes contribute the most to tank-bottom sludges. [24] Fig. 9.8 shows the generic molecular structures of n-paraffins, iso-paraffins, and naphthenes. The n-heptane structure is an example of a "normal" paraffin; 2-methyloctane is an "iso" paraffin and n-butylcyclopentane is a naphthene. These specific n-paraffins and naphthenes are too small to crystallize as wax deposits (i.e., outside the carbon-number range specified above). The drawings illustrate the type of structures involved.


Waxes isolated from crudes can contain various amounts of all classes: n-paraffins, naphthenes, and iso-paraffins. For example, waxes derived from several Venezuelan crudes[24] showed n -paraffin/(cyclo + iso paraffin) ratios ranging from 1.28 to 0.23. The iso-paraffins of the 2-methyloctane type (Fig. 9.8) are more likely to be included in a wax deposit than the more highly branched alkanes.

A "clean waxy crude" is defined as a crude oil that consists of only hydrocarbons and wax as the heavy organic constituents. "Regular waxy crudes" contain other heavy organics in addition to the waxes (e.g., asphaltenes and resins). These heavy organics have interactions with the crude, which can either prevent wax-crystal formation or enhance it.

Phenomenology. As the temperature of the crude drops below a critical level and/or as the low-molecular-weight hydrocarbons vaporize, the dissolved waxes begin to form insoluble crystals. The deposition process involves two distinct stages: nucleation and growth. Nucleation is the forming of paraffin clusters of a critical size ("nuclei") that are stable in the hydrocarbon fluid. This insoluble wax itself tends to disperse in the crude.

Wax deposition onto the production system ("growth") generally requires a "nucleating agent," such as asphaltenes and inorganic solids. The wax deposits vary in consistency from a soft mush to a hard, brittle material. Paraffin deposits will be harder if longer-chain n-paraffins are present. paraffin deposits can also contain asphaltenes, resins, gums, fine sand, silt, clays, salt, and water. [25] High-molecular-weight waxes tend to deposit in the higher-temperature sections of a well, while lower-molecular-weight fractions tend to deposit in lower-temperature regions. Prior to solidification, the solid wax crystals in the liquid oil change the flow properties from a Newtonian low viscosity fluid to a very-complex-flow behavior gel with a yield stress.

Coping With Waxes. The primary chemical parameter to establish is the critical temperature at which these wax nuclei form—the "wax appearance temperature" (WAT). The WAT (or "cloud point") is highly specific to each crude. The WAT value is a function of oil composition; cooling rate during measurement; pressure; paraffin concentration; molecular mass of paraffin molecules; occurrence of nucleating materials such as asphaltenes, formation fines, and corrosion products; water/oil ratio; and shear environment. [26] A variety of experimental methods have been used to obtain this number. Among these are differential scanning calorimetry (DSC), cross polarization microscopy (CPM), filter plugging (FP), and Fourier transform infrared energy scattering (FTIR).

DSC measures the heat released by wax crystallization. CPM exploits the fact that insoluble wax crystals rotate polarized light, but liquid hydrocarbons do not. FP measures the increase in differential pressure across a filter, which can be attributed to wax-crystal formation. FTIR detects the cloud point by measuring the increase in energy scattering associated with wax solidification. Each of these techniques has its advantages and disadvantages. A comparison/review of these methods is found in Monger-McClure, Tackett, and Merrill.[27] In testing, cloud points, measured by each of the four methods, agreed with the average value of all methods within 3 to 5°F.

The second, and more important, question is how well do laboratory-measured cloud points anticipate WATs found in the field. Measured cloud-point data should only match field results for wells producing at low shear (high shear rates tend to delay the deposition of waxes). Another inherent problem is that the cloud-point measurement sees the precipitation of the most insoluble paraffin, not the mass of lower-molecular-weight paraffins that might contribute the major amount of wax deposit. Nevertheless, CPM measurements have been found to correlate well with the temperature at field deposition, more so than optical techniques that required a greater mass of wax to register a signal. [26] A major problem in correlating these measurements and simulations (discussed later) with field experience is the acquisition of good field data. [27] Illustrative of the state of the art in interpreting these measurements is that closer agreement is found between stock-tank oil measurements and field experience, even though it is live oil that is being produced.

An alternative to the measurement of cloud point is its prediction from compositional data by thermodynamic models. These models can predict cloud point as the temperature at which the first infinitesimal amount of wax appears, as well as predicting that mass of wax precipitating out of solution that, from experience, corresponds to field deposition. [28] Models that use detailed n-paraffin composition input data, as obtained from high-pressure gas chromatography, generally outperform models based on less specific information like compositions to C7+ [the numbers are more generally available in the routine pressure/volume/temperature (PVT) reports].

Simulation of Deposition During Production. Given the cloud point, what is the propensity for wax precipitation during the production and, in particular, the pipelining and processing of the crude? This is the regime of "paraffin deposition models." These are engineering simulators used to predict wax buildup in flowing systems, taking into account such parameters as heat transfer, phase behavior of the crude, flow regime, wax deposition kinetics, shear rate, diffusivity, wall conditions (roughness, coatings, scale), and produced-water/oil ratio. One such model currently in use is "ParaSim™" (AEA Technology, U.K.). More extensive programs are under development. [29]

Prevention/Inhibition. As with other solids-depositing problems, prevention can be more cost effective than removal. One key to wax-deposition prevention is heat. Electric heaters can be employed to raise the crude-oil temperature as it enters the wellbore. The limitations are the maintenance costs of the heating system and the availability of electrical power. And, as with the hydrate problem, which is discussed below, maintaining a sufficiently high production level may also keep the upper-wellbore temperature above the WAT. In addition, high flow rates tend to minimize wax adherence to metal surfaces because of the shearing action of the flowing fluid. Insulated pipelines are also an alternative to minimize, if not eliminate, the problem; costs can be prohibitive for long pipelines.

Wax deposition can be prevented, delayed, or minimized by the use of dispersants or crystal modifiers. As with asphaltenes, the paraffin-wax characteristics vary from well to well. Thus, chemicals that are effective in one system are not always successful in others, even for wells within the same reservoir. "For this reason it is of fundamental importance to establish a good correlation between oil composition and paraffin inhibitors efficiency, leading to an adequate product selection for each particular case, avoiding extremely expensive and inefficient 'trial-and-error' procedures." [24]

Paraffin-crystal modifiers are chemicals that interact with the growing crude-oil waxes by cocrystallizing with the native paraffin waxes in the crude oil that is being treated. These interactions result in the deformation of the crystal morphology of the crude-oil wax. Once deformed, these crystals cannot undergo the normal series of aggregation steps. Types of paraffin-crystal modifiers include maleic acid esters, polymeric acrylate and methacrylate esters, and ethylene vinyl acetate polymers and copolymers.

Dispersants act to keep the wax nuclei from agglomerating. Dispersants are generally surfactants and may also keep the pipe surface water wet, minimizing the tendency of the wax to adhere. Some water production is required, of course. High levels of water alone may maintain the system in a water-wet state. As with scale prevention, a smooth surface tends to decrease wax adherence. However, the operational problem is to maintain such a surface for an extended period of time. Various forms of erosion are highly detrimental.

Obviously, these inhibitors must be delivered into the crude oil at temperatures above the WAT. This need not cause a problem for surface equipment; it could cause a problem for wellbore treatment, if the bottomhole temperatures are low.

Removal. Removal of wax deposits within a wellbore is accomplished by cutting, drilling, chemical dissolution, or melting—the use of hot oil, hot water, or steam. Of these, the use of hot oil has been the most popular, normally pumped down the casing and up the tubular. It is intended that the high temperature of the liquid phase heat and melt the wax, which then dissolves in the oil phase. Using the bottom-up delivery approach, hot oil first reaches those waxes most difficult to melt. The higher in the tubular the hot oil proceeds, the lower its temperature becomes, thereby reducing its wax-carrying capacity. Hot oiling can cause permeability damage if the fluid containing the melted wax enters the formation. [25]

Hot water, hot-water/surfactant combinations, and steam are alternatives to hot oiling. Plain hot-water treatments do not provide the solvency required to remove the wax, hence the use of surfactants to disperse the wax. The advantage of water is its greater heat capacity.

Chemical generation of heat has also been proposed as a method of melting wax deposits. One field-tested scheme uses the thermochemical process of reacting two specific nitrogen salt solutions, acidic ammonium chloride and sodium nitrite; [30] an orgainc solvent is included to keep the wax in solution after the system has cooled.

Various aromatic solvents can be used to dissolve the wax. These are generally not heated, relying solely on the solvency properties of the fluid. As with asphaltene dissolution, o -xylene has been one of the more effective solvents for waxes; kerosene and diesel tend to be poor solvents. However, as with asphaltenes dissolution, one solvent does not necessarily work equally well on all wax deposits; an example of solvent screening procedures is given in Ferworn, Hammami, and Ellis.[31]

Pigging is the primary mechanical method of removing wax buildup from the internal walls of pipelines. The pig cuts the wax from the pipe walls; a bypass can be set with a variable-flow pass, allowing the pig to prevent wax buildup in front. Pig sizing can vary, and multiple pig runs with pigs of increasing size can be used. For subsea pigging, a looped flowline is required or a subsea pig launcher for a single flowline. The major uncertainty in this operation is the wax hardness as it is formed in the pipeline.

Coiled tubing with the appropriate cutters at the end also can be used for wax removal—the drawback for pipeline cleaning being the limited reach of the coiled tubing. For wellbore cleaning this is obviously less of a problem.

Toxic-Materials Production

Various toxic materials are coproduced with the hydrocarbons. Their removal and disposal will be discussed elsewhere in more detail. A brief overview is given here.

Hydrogen sulfide is highly toxic. If the oil or gas is sour, there is no alternative but to produce the H2S and, because it generally has minimal economic value, dispose of the gas in a safe and cost-effective manner. The treatment procedure and treatment location depend on the concentration of H2S. Caustic scrubbing can be used for the removal of high concentrations. [32] Treatment of the low-concentration H2S (nominally < 150 ppm) is made using nonregenerative chemical technology that is more efficient at low H 2 S concentrations. Chlorine dioxide and nitrite ion[33][34] are two such low-cost treatment chemicals.

Mercury is also is a naturally occurring contaminant found primarily in natural gas. As with hydrogen sulfide, there is little alternative but to produce it and then remove it—generally at a central treating plant rather than on site. The occurrence of mercury in quantity and location is discussed in Wilhelm.[35] Regulations exist restricting the amount present in natural gas for sale.

NORM, such as radium and radon, are generally not considered a serious well-production problem. The sources of NORM in oil and gas production are sedimentary rocks. [36] Radon gas and radium are to be expected in many formation waters. Radium is similar in chemistry to calcium and, particularly, barium. Radium sulfate coprecipitates with barium sulfate and is concentrated in barite scale. The radioactive daughter product, radon, is also trapped within the barite deposit. Coprecipitated radium sulfate can require radioactivity decontamination procedures during scale removal. About 30% of the producing wells in the U.S. are contaminated with radioactive salts. Radioactive scales also are found in oil/gas fields in the North Sea, in practically all main producing areas of the former Soviet Union, as well as other regions of the world. [37] Radioactive lead (Pb210) has been found in southern U.K. gas fields as metallic lead and lead sulfide. [38] Prevention of barite precipitation is preferred for minimizing the consequences of NORM. [36][39]

Water-Related Production Problems


All oil fields under waterdrive, either from waterflood or a natural aquifer, eventually produce water along with oil. Even gas-cap and depletion reservoirs may produce some water. This coproduction of water causes an additional set of problems: corrosion, scale/salts deposition, gas-hydrate formation, and disposal of the water itself. Water coproduction also tends to exacerbate hydrocarbon-solids deposition. Discussed first in this section is the gas-hydrate problem: the possibility of solids formation because of the coproduction of water and light ends. This is followed by a discussion of water control: avoiding lifting unnecessary water and disposing of the water. The final portions of this section deal with inorganic-scale deposition and metal corrosion.

Hydrates

Natural-gas hydrates are ice-like solids that form when free water and natural gas combine at high pressure and "low" temperature. This can occur in gas and gas/condensate wells, as well as in oil wells. Location and intensity of hydrate accumulations in a well vary and depend on the operation regime, design, geothermal gradient in the well, fluid composition, and other factors. Detailed reviews of gas-hydrate chemistry, physics, and oilfield engineering are found in a pair of sources.[40][41]

At the appropriate combinations of temperature, pressure, and low-molecular-weight gases, water molecules arrange themselves into coplanar 5- or 6-membered rings, which then form three-dimensional (3D) polyhedra around the gases (tetradecahedrons, dodecahedrons, and hexadecahedrons). These individual polyhedra then combine to form specific crystalline lattices. In these solids, one volume of water in the hydrate state may "enclathrate" 70 to 300 volumes of gas. Such solids can be formed with N2, H2S, CO2, C1, C2, C3, and iso-butane. Larger molecules like n-butane and cyclopentane require the presence of some smaller molecules. Natural-gas hydrates are to be distinguished from the common inorganic-salt hydrates such as CuSO4•5H2O.

A general phase diagram for water, hydrocarbon, and solid hydrate is shown in Fig. 9.9. There are essentially five regions: 1) hydrate + gaseous hydrocarbon (+ excess liquid water); 2) hydrate + liquid hydrocarbon (+ excess liquid water); 3) ice + gaseous hydrocarbon; 4) liquid water + gaseous hydrocarbon; and 5) liquid water + liquid hydrocarbon.


The temperatures at which gas hydrates form are significantly higher than the temperatures at which water ice will form. The exact PT values for this equilibrium vary with hydrocarbon-gas composition and with the dissolved salt content in the liquid water phase. (This salt will not enter the gas-hydrate crystal structure, but it will control the chemical activity of the water from which the hydrate forms.) Hydrates can form more readily (i.e., at higher temperatures) from oil than in pure methane. [41]

Shut-in gas wells are particularly prone to serious hydrate problems if the well has been producing some water. Subsequent equilibration of the tubular and its contents with cold zones of the rock can lower the temperature into the hydrate-formation region. Hydrate nuclei form from the films of water on the tubular walls. The subsequent crystallization can result in large plugs of hydrate tens or hundreds of meters long.

Hydrate formation also can take place within a shut-in oil well, generating a slurry of solid that is capable of accumulating and plugging the pipe. [40] The logic is that oil will dissolve some water—generally small amounts. Under high-temperature/high-pressure (HT/HP) conditions, the amounts can be 5 to 10 mol% (at 300°F). The oil is produced up the wellbore, temperature falls, and liquid water comes out of solution, remaining in suspension as microdroplets. In a static condition, the microdroplets gradually coalesce and precipitate. This liquid water is saturated with gas so that hydrates can form at the appropriate PT values.

Coping With Hydrate Formation. The first step in controlling hydrate formation is to understand which pressure and temperature conditions/locations in the specific system are conducive to gas-hydrate formation. A number of computer simulators are available for this purpose, [42][43][44][45] usually as adjuncts to more general phase PVT simulators. The models vary in how well they compute the chemical activity of the water phase, the effect of higher-molecular-weight hydrocarbons, and the effect of hydrate inhibitors (see the discussion that follows). A comparative assessment of models is given in Sawyer et al.[46] Fig. 9.10 shows the results of simulations with one of the models—the line is computed, the dots are experimental points. [44] Besides the dissociation PT points for the hydrate, the information required and derivable from such models is the amount of hydrate formed, the composition of all phases, and the distribution of inhibitors throughout all phases.


The second control step is the comparison of this information with the measured or expected PT profile within the production system. A method of coping with hydrate formation is then selected (e.g., producing the hydrocarbons under conditions that avoid the hydrate PT formation zone or using a suitable inhibition method. The simulator should also be capable of evaluating the consequences of the inhibitor strategy. An example of adjusting production conditions to avoid hydrate formation is PT curves for producing wet gas at various rates. [47]

The alternative to production control is the use of inhibitors. These are classified as environmental inhibitors, thermodynamic inhibitors, and kinetic inhibitors. The conceptually simplest "environmental inhibition" method is to dry the gas before it is cooled—remove the water and hydrates so they cannot form. This involves adsorption onto, for example, silica gel, or cooling and condensation, absorption of water into alcohols, or adsorption onto hydroscopic salts.

"Thermodynamic inhibition" has been the most common method for controlling gas hydrates. There are a number of alternatives: heating the gas, decreasing pressure in the system, injecting salt solutions, and injecting alcohol or glycol.

One method of providing heat to the hydrate-formation zone is the use of electrical-resistance heating via cables connected to a transformer. [41] Another is placing the choke in a sufficiently hot zone of the production system. The injection of salts (primarily CaCl2) reduces hydrate formation by lowering the chemical activity of water, and by lowering the solubility of gas in water.

Alternative four is used more frequently now with a transition from methanol to ethylene glycols for HSE reasons. The general effect of such inhibitors is shown in Fig. 9.11 (not a total removal of the problem but a shift of the hydrate-formation curve to lower temperatures, ostensibly outside the PT production regime). It is possible to compute this phase diagram for gas/water/methanol or the glycols with reasonable accuracy. The major drawback to this inhibition technique is the large quantity of methanol or glycol required. This impacts both operating costs and logistics, particularly important for offshore wells and pipelines. [48]


Such problems have resulted in the search for kinetic hydrate inhibitors[49] —low-dosage chemicals that, as with asphaltenes, waxes, and inorganic scales, prevent the growth of hydrate nuclei or prevent the agglomeration of nuclei into large crystals (also called "threshold hydrate inhibitors"). Klomp, Kruka, and Reijnhart.[50] describes the field testing of such inhibitors. The compounds were primarily quaternary ammonium salts; polymeric n-vinyl-2-pyrrolidone was particularly effective. The application of kinetic hydrate inhibitors to black-oil flowlines is described in Pakulski, Prukop, and Mitchell.[51] The additive here was a methanol-based solution of the polymer n-vinyl, n-methyl acetamide-covinyl caprolactam ("VIMA-VCap"). In the example given, the dose rate was low (0.5 gal/D in 16 B/D of produced water). Nonpolymeric gas-hydrate inhibitors have been successfully field tested on an offshore platform containing gas lift injection wells, [52] and they have been used in long wet-gas subsea pipelines. [52] A novel gas-hydrate inhibitor controlling hydrate formation during startup uses a borate-crosslinked gel system; [53] this inhibited gel system ostensibly also exhibits fracturing-fluid performance equal to that of more conventional borate-gel systems.

Removal of Solid Hydrates. Solid hydrates are removed with many of the same chemicals and technology used to inhibit hydrate formation. The simplest method is, if possible, to reduce pressure above the hydrate plug sufficiently enough to reverse the equilibrium reaction. Addition of solvents, such as alcohols and glycols, is the most common technique (well completions will often provide for a methanol-injection line). An example of hydrate-plug removal with coiled-tubing jetting from a deepwater test well is given in Reyma and Stewart.[54] Chemical heating, such as described for wax removal, has been used. [40]

Water Control

The material presented in this section that deals with water control technology has been abstracted from a recent review of water problems and control technology. [55] This review contains the references to the original literature. Water disposal is discussed elsewhere.

The Problem. The present worldwide daily water production from oil wells is roughly 3 BWPD per barrel of oil. It costs money to lift water and then dispose of it. In a well producing oil with 80% water cut, the cost of handling water can double normal lifting costs. Yet, wells with water cuts in excess of 90% may still produce sufficient hydrocarbons to be economical (e.g., certain wells in the North Sea Shell Expro Brent fields and in the BP-Amoco Forties fields). "Water control technology" is intended to reduce the costs of producing water.

It is not necessary, nor desirable, to completely shut off the coproduced water. The logic here is the distinction between "good" (necessary) and "bad" (excess) water. [55] "Good" water is that water produced at a rate below the water/oil economic limit (i.e., the oil produced can pay for the water produced). "Good" water, then, is that water that cannot be shut off without reducing oil production. The fractional water flow is dictated by the natural mixing behavior that gradually increases water/oil ratio (WOR). "Good" water is also caused by converging flowlines from the injector to the producer wellbore. Water breakthrough on injection occurs initially along the shortest (least resistant) flow path between injector and producer, while oil is still being swept along other flow paths.

"Bad" water is water produced into the wellbore that produces no oil or insufficient oil to pay for the cost of handling the water. The remainder of this discussion deals with "bad" water.

Phenomenology. There is no one mechanism for "bad" water intrusion, and there is no one technology that will shut off water intrusion. There are 10 basic types of water problems. [55] The first four problems, which are listed next, are relatively easily controlled; the next two are more difficult but control is still feasible. The last four problems do not lend themselves to simple and inexpensive near-wellbore solutions and require completion or production changes as part of the reservoir management strategy (e.g., multilateral wells, sidetracks, coiled-tubing isolation, and dual completions). Mechanisms for water intrusion are as follows:

  • Casing, tubing, or packer leaks.
  • Channel flow behind the casing from primary cementing that does not isolate water-bearing zones from the pay zone.
  • Moving oil/water contact (OWC).
  • Watered-out layer without crossflow—this is a common problem with a multilayer production and high-permeability zone isolated with flow barriers (e.g., a shale bed) above and below the zone. It is shown schematically in Fig. 9.12. [55]
  • Fractures or faults between injector and producer.
  • Fractures or faults from a water layer. Water can be produced from fractures that intersect a deeper water zone.
  • Coning or cusping. Coning occurs in a vertical well when there is an OWC near the perforations with a relatively high vertical permeability driving high flow rates.
  • Edge water from poor areal sweep. Areal permeability anisotropy causes this problem.
  • Gravity-segregated layer. In a thick reservoir layer with high-vertical permeability, water, either from an aquifer or injector, slumps downward in the permeable formation and sweeps only the lower part of the reservoir (Fig. 9.13). [55]
  • Watered-out layer with crossflow. This is difficult, if not impossible, to treat.



Effective water control is generally predicated on knowing the position and mechanism (source) of the intruding water. These parameters may be established from direct measurement, the well's production logs, and production history.

"Accurate production logs…can show water entry into the wellbore. The tool can determine flow and holdup for each fluid phase in vertical, deviated and horizontal wells. The addition of new optical and electrical sensors incorporating local probe measurements and phase velocity measurements have resulted in major improvements in the diagnosis in both complex and simple wells with three-phase flow. Such advances in reliable and accurate production logging, particularly in deviated wells with high water cuts represent a major step forward in identifying and understanding water problem types. A production log can be turned into a multilayer production log or a 'multilayer test' by measuring the production rate of each layer at several different producing pressures with station measurements positioned between each layer. In this way, crossflow potential can be measured. Wireline formation pressure measurements such as those with the MDT [modular formation dynamics tester] tool or the repeat formation tester (RFT) tool can show if the layers are in communication. A vertical interference test performed with the MDT tool will show vertical permeability near the wellbore. Log correlations can demonstrate whether extensive shale permeability exists across a field. A production log (spinner) may detect wellbore crossflow during well shut-in." [55]

Production history can be used in a number of ways. First, there is the "recovery plot": a semilog plot of WOR vs. cumulative production, allowing extrapolation to the WOR economic limit (where producing water equals the value of the oil produced). If extrapolated production is approximately equal to the expected reserves, the well is producing acceptable ("good") water and no water control is necessary. Next, there is the production history itself—a log/log plot of oil/water rates vs. time. Good candidates for water control show an increase in water production and a decrease in oil production at about the same time. Also, there is the decline-curve analysis: a semilog plot of oil production vs. cumulative oil. A sudden increase in decline may indicate a water problem or severe pressure depletion caused by damage buildup. And finally, there are diagnostic plots: log/log plots of WOR vs. time. Three basic signatures (patterns) distinguish between different water-breakthrough mechanisms (Fig. 9.14). [55]


Shut-in and choke-back analysis of the fluctuating WOR data can, sometimes, provide clues to the problem type. Water-entry problems such as coning or a single fracture intersecting a deeper water layer will lead to a lower WOR during choke-back or shut-in. Fractures or a fault intersecting an overlying water layer have the opposite effect.

Injector Problems. There can be additional problems associated with the injector well—primarily because of unplanned and uncontrolled fracturing of the receiving reservoir. One mechanism arises from the buildup of solids because of, for example, filtration, bacterial action, scale buildup, or changes in reservoir wettability. Pressure is increased to maintain injectivity and fracturing may occur. Thermal fracturing is often encountered offshore because of the stress reduction in the injection zone from cool-down. The zone with the highest injectivity cools down first and fractures, taking even more injection fluid—hence, poor sweep efficiency. One strategy to control this problem is to deliberately fracture all receiving zones, increasing sweep efficiency.

Coping With Water Production. Mechanical or inflatable plugs are often the solution of choice for the near-wellbore problems: casing leaks, flow behind casing, rising bottom water, and watered-out layers without crossflow. These plugs can be deployed on coiled tubing or wireline to ensure shutoff in cased and openhole environments. When the wellbore must be kept open to levels deeper than the water entry, a through-tubing patch may be deployed inside the casing. One technology involves placing a flexible, inflatable composite cylinder made of, for example, carbon fiber, thermosetting plastics, and a rubber skin opposite the area to be treated. A pump then inflates the sleeve and injects well fluid, which heats the resins, turning on the polymerization process. After the resins have set, the sleeve is deflated and extracted.

Rigid gels are highly effective for near-wellbore shutoff of excess water. Unlike cement, gels can be squeezed into the target formation to give complete shutoff of that zone or to reach shale barriers. They have operational advantages over cement treatments because they can be jetted rather than drilled out of the wellbore. Commercial gels can be bullheaded into the formation to treat problems such as flow behind casing and watered-out layers without crossflow, or they can be selectively placed in the water zones using coiled tubing and a packer.

Certain crosslinked polymers can also have long working times before becoming rigid. They are injected into small faults or fractures but only penetrate formations with permeabilities greater than 5 darcy. Large volumes (1,000 to 10,000 bbl) of these inexpensive fluids often successfully shut off extensive fracture systems surrounding waterflood injector or producing wells.

Gel treatments are not generally successful for combating coning/cusping problems for prolonged times because they require very large volumes to be effective. An alternative is to drill one or more lateral drainholes near the top of the formation to take advantage of the greater distance from the OWC and decreased drawdown. Another approach is a dual drain (Fig. 9.15). [55]


Gel treatments are also not likely to work on the "gravity-segregated-layer" problem. Lateral drainholes may be effective in accessing the unswept oil. Infill drilling is often the best approach to improving the areal sweep efficiency edgewater problem. A large, likely uneconomic treatment of gel would be required to divert the injected water away from the pore space that has already been swept by water.

Treatments for water problems in horizontal wells are most effective when the treatment zone is isolated from the remainder of the wellbore. In cased holes, this is achieved mechanically with packers. However, when a screen or liner has been run but left uncemented, such mechanical devices are not effective in isolating the open annular space behind the pipe. One product developed for such situations is the annular chemical packer (Fig. 9.16).


Proactive water control includes choking back zones with high permeability to create a more uniform sweep. This means sacrificing early cash flow for an uncertain return because of incomplete knowledge of heterogeneity. The production (and injection) profile can be improved through selective stimulation of zones with lower permeability. Coiled tubing is used to precisely place these small hydraulic fractures.

Disposal. Whether water production is minimized or not, some water (e.g., "good" water) will be produced and must be disposed. To minimize costs, the water should be removed as early as possible (e.g., with a downhole separator if possible); see Fig. 9.17.[55] The method for disposal at the surface will be discussed elsewhere.

Inorganic-Scale Formation

Wells producing water are likely to develop deposits of inorganic scales. Scales can and do coat perforations, casing, production tubulars, valves, pumps and downhole completion equipment, such as safety equipment and gas lift mandrels. If allowed to proceed, this scaling will limit production, eventually requiring abandonment of the well. Technology is available for removing scale from tubing, flowline, valving, and surface equipment, restoring at least some of the lost production level. Technology also exists for preventing the occurrence or reoccurrence of the scale, at least on a temporary basis. "Temporary" is generally 3 to 12 months per treatment with conventional inhibitor "squeeze" technology, increasing to 24 or 48 months with combined fracture/inhibition methods. (See the discussion that follows.)

Phenomenology. As brine, oil, and/or gas proceed from the formation to the surface, pressure and temperature change and certain dissolved salts can precipitate. This is called "self-scaling." If a brine is injected into the formation to maintain pressure and sweep the oil to the producing wells, there will eventually be a commingling with the formation water. Additional salts may precipitate in the formation or in the wellbore (scale from "incompatible waters"). The chemical formulae and mineral names for most oilfield scales are shown in Table 9.1.


The most common oilfield scales are calcite, barite, celestite, anhydrite, gypsum, iron sulfide, and halite. "Exotic" scales such as calcium fluorite, zinc sulfide, and lead sulfide are sometimes found with HT/HP wells. Many of these scaling processes can and do occur simultaneously. Scales tend to be mixtures. [57] For example, strontium sulfate is frequently found precipitated together with barium sulfate.

Calcite deposition is generally a self-scaling process. The main driver for its formation is the loss of CO2 from the water to the hydrocarbon phase(s) as pressure falls. This removes carbonic acid from the water phase, which had kept the basic calcite dissolved. Calcite solubility also decreases with decreasing temperature (at constant CO2 partial pressure).

Halite scaling is also a self-scaling process. The drivers are falling temperature and evaporation. Halite solubility in water decreases with decreasing temperature, favoring halite dropout during the production of high-total-dissolved solids brines to the surface. (Falling pressure has a much smaller effect on decreasing halite solubility.) Evaporative loss of liquid water is generally the result of gas breakout from undersaturated condensate and oil wells, as well as the expansion of gas in gas wells. This increase in water vapor can leave behind insufficient liquid water to maintain halite solubility in the coproduced brine phase. Halite self-scaling is found with both high-temperature and low-temperature wells [e.g., with 125 and 350°F bottomhole temperature (BHT) gas/gas condensate wells].

Barite scales are generally the result of mixing incompatible waters. For example, seawater is often injected into offshore reservoirs for pressure maintenance. Seawater has a high-sulfate content; formation waters often have high-barium contents. Mixing these waters results in barite deposition. If this mixing/precipitation occurs within the reservoir far removed from a vertical wellbore, there will generally be little impact on the production of hydrocarbons. Mixing/precipitation near or within the wellbore will have a significant impact on production. Mixing of incompatible waters within the sandpack of a hydraulically fractured well can also be detrimental to production. Furthermore, after the initial, large deposition of scale, this water continues to be saturated in barite and additional barite scale will continue to form in the wellbore as pressure and temperature fall.

Waterfloods combining ground waters with high calcium and high sulfate contents can deposit anhydrite or gypsum by much the same "incompatible waters" mechanism discussed for barite. However, calcium sulfate scale solubility, unlike that of barite scale, actually increases with decreasing temperature (until about 40°C). This can decrease the likelihood of scale after the initial mixing deposition. The reversal in solubility falloff below 40°C accounts for the gypsum scaling observed in surface equipment. This inverse temperature effect can result in the generation of anhydrite scale when injecting seawater. Anhydrite solubility falls as pressure falls; data could not be found for gypsum solubility vs. pressure.

Iron sulfide scales are almost ubiquitous when hydrogen sulfide is produced—frequently the result of tubular corrosion in the presence of H2S. A review of the iron sulfide chemistry and phases occurring in production equipment is contained in a couple of sources.[58][59]. Suffice it to say, the chemistry is complicated; more than one iron sulfide phase can be present. The physical properties of the phases vary (sometimes dense, sometimes not), and the phase composition can change with time.

These multistep scale/water chemistries can be simulated with present day computer software. Some of the programs are commercial; some operators have their own in-house programs. In effect, the code sets up a series of equilibrium equations for each possible scale and solution ion/ion reaction, as well as solution-gas reaction, then solves them simultaneously as a function of input pressure, temperature, gas composition, and water-phase composition. These are referred to as "thermodynamic models." As of 2001, the software had not yet reached a level of sophistication sufficient to say, reliably, how fast these solids can form during production. This has resulted in a series of "rules-of-thumb," correlating an operator's field experience with the thermodynamic simulator's output. Such rules of thumb are much less necessary for formation scaling, particularly if the mineral is naturally present in the formation (e.g., calcite). Computer simulation of scaling tendencies for produced oilfield brines has found considerable acceptance and application. Examples of this technology, applied to halite and calcite scaling in HT/HP wells, are in more than one source.[60][61]

Scaling Economics. Scale remediation and prevention come at a cost, and a major theme in the oil patch has always been to "cut costs." It is becoming more appropriate to think of scale control in terms of "value added"—obviating the consequences of not remediating or preventing scale formation, and so increasing the total revenue from a well, as well as possibly extending its lifetime. [62] The effects of scale can be quite expensive and rapid. In one North Sea well (Miller field), production fell from 30,000 B/D to zero in just 24 hours because of scaling. The cost for cleaning out the single well and putting it back on production was approximately the same as the chemical costs to treat the entire field. [63] While not all wells are susceptible to such momentous penalties for allowing scaling to initiate, there is no question that scale formation, remediation, and prevention have associated costs. The cost savings because of less deferred/lost oil can result in substantially increased revenue over the life of the well, as well as more oil. [62]

It is anticipated that oilfield scaling problems will continue to worsen and become more expensive. [64] The new drivers are the tendencies to longer tiebacks; the use of smart wells (integrity more critical); more gas production (gas-well formations tend to be more delicate); the need to use greener chemicals; and the increasing large amounts of produced water.

Coping With Scale Production. Scale control has tended to be reactive rather than proactive. There are a variety of methods of removing the effects of scale on production. The first step is to determine which scales are forming and where they are forming. Some of this information can be reliably inferred from the computer simulation procedures discussed, particularly for self-scaling processes. The simplest method of physically detecting scale in the wellbore is to run calipers down the wellbore and measure decreases in the tubing inner diameter. Gamma ray log interpretation has been used to indicate barium sulfate scale because naturally radioactive radium (Ra226) precipitates as an insoluble sulfate with this scale. An example of this technology is shown in Fig. 9.18. Visual observation with the appropriate wireline tools has also been used to show the presence of calcite and halite solids within the wellbore.


The onset of water production coinciding with simultaneous reduction in oil production is a sign of potential scale problems. It is quite possible, particularly with gas wells, to produce water below the limit of detection of surface analysis (nominally 1 or 2%). This water will evaporate and leave its dissolved solids behind, as scale. Because the amounts of water are small, the amounts of solids per unit volume of water will be small, but the solids will accumulate with time. The same idea applies to the appearance at the surface of liquid "fresh" water when the reservoir brine is known to be brackish. This can be condensed water because of falling temperature. When a few percent of liquid water is produced, it is prudent to track the dissolved ion content with time. Injection-water breakthrough is generally signaled by dramatic changes in the concentrations of scaling ions, such as barium or sulfate, which coincide with reduced oil production.

Early warning of scaling conditions downhole would be valuable. Wells with intelligent completions and permanent monitoring systems are being designed to contain scale sensors. The function of the scale sensor is double duty—not only to provide early warning about the initiation of production impairment by scale generation but also to provide information about possible impairment of the smart-well sensors and valves by films of scale.

Scale remediation techniques must be quick and nondamaging to the wellbore, tubing, and the reservoir. If the scale is in the wellbore, it can be removed mechanically or dissolved chemically. Selecting the best scale-removal technique for a particular well depends on knowing the type and quantity of scale, its physical composition, and its texture. Mechanical methods are among the most successful methods of scale removal in tubulars. When pulling costs are low (e.g., readily accessible and shallow land locations), often the least expensive approach to scaling is to pull the tubing and drillout the scale deposit.

Scales are generally brittle. One of the earliest methods used to break off the thin brittle scale from pipes was explosives: a strand or two of detonation cord ("string shot") placed with an electronic detonation cap at the appropriate location in the wellbore, most effectively at the perforations. Thicker scales require more stringent means. Impact bits and milling technologies have been developed to run on coiled tubing inside tubulars using a variety of chipping bits and milling configurations. Such scale-removal rates are generally in the range of 5 to 30 linear ft/hr of milling.[65]

An alternative to milling and drilling is jetting.[65] Fluid jetting systems have been available for many years to remove scales in production tubing and perforations. These tools can be used with chemical washes to attack soluble deposits where placement is critical. Water jetting can be effective on soft scale, such as halite, but is less effective on some forms of medium to hard scales such as calcite and barite. The use of abrasive slurries greatly improves the ability of jets to cut through scale but can damage the steel tubulars and valves.

"Sterling beads" is an alternative abrasive material for scale removal by jetting.[65] This material matches the erosive performance of sand on hard, brittle scales, while being 20 times less erosive of steel. Sterling beads do not damage the well if prolonged jetting occurs in one spot. The beads are soluble in acid and have no known toxicity, simplifying use and cleanup. Hard scales, such as barite, are removed at rates > 100 ft/hr. This tool is capable of descaling configurations other than wellbore tubing (e.g., removing hard barite scale deposits on two gas lift valves in a multiple-mandrel gas lift completion).

Dissolution. Chemical dissolution of certain wellbore scales is generally relatively inexpensive and is used when mechanical removal methods are ineffective or costly. Carbonate minerals are highly soluble in hydrochloric acid; therefore, they can easily be dissolved. Bullheaded "acid washes" are commonly used to remove calcite accumulations within the wellbore.

Sulfate scale is more difficult to remove from the wellbore because the scale has a low solubility in acid. Chelants (scale dissolvers) have a high thermodynamic driving force for dissolving sulfate scales such as barite, isolating and locking up the scale metallic ions within their closed cage-like structures (Fig. 9.19). These chemicals are successful at removing films of sulfate scale from the wellbore. However, they are slow in dissolving the larger particle-sized wellbore scales and plugs—the reaction rates are surface-area limited; treatments are time-consuming, thus expensive.


Iron sulfides are soluble in hydrochloric acid. Many HCl corrosion inhibitors are also effective in inhibiting the iron sulfide from dissolution, as well as the tubular steel. There are now exceptions: inhibitors that protect the steel and not the scale, as well as being compatible with scavengers for the toxic hydrogen sulfide that is generated. [66]

For halite, dilution with low-salinity water is sufficient to prevent its accumulation in the wellbore and to dissolve halite that may have accumulated in the wellbore. This requires a source of fresh or brine-treated water to help prevent other scaling problems, which can be expensive. A case in point is the use of a desulfation plant to remove sulfate ion from the halite wash water for the Heron field production. [56]

Some scales and scaling situations are "chemically difficult." Fluorite scale, found with some HT/HP brines, has no known solvent (as of the date of this writing). Access of the scale-dissolver chemical to the inorganic scale can be blocked by organic deposits (e.g., asphaltenes).

Inhibition. Inhibitors are typically used after remediation to prevent further scaling. Obviously, this same technology can be used to do pre-emptive scale control. The effectiveness of inhibition is related to the degree of scale supersaturation—the higher this value, the more difficult it is to inhibit. For example, barite solutions with saturation indices > 350 are particularly difficult to inhibit.

Scale precipitation can be avoided by chelating the scaling cation. This is costly because the reactions are "stoichiometric," (e.g., one chelant molecule per one scaling cation). More effective are chemicals that poison the growth of scale. These are "threshold" inhibitors, effectively inhibiting mineral scale growth at concentrations of 1,000 times less than a balanced stoichiometric ratio. Most inhibitors for inorganic scales are phosphorous compounds: inorganic polyphosphates, organic phosphate esters, organic phosphonates, organic aminophosphates, and organic polymers. A variety of such chemicals is well-known, and they are available from many companies. Two chemical structures are shown in Fig. 9.20. These are used for the various carbonate and sulfate scales. Recently, the successful use of a nonphosphorus compound to inhibit halite precipitation has been described and field tested at moderate temperatures; [67] more classical amine-based halite salt inhibitors are also available for halite inhibition. [68]


Delivering the inhibiting solution to the scaling brine in the tubular has been done by a number of means: continuous injection into the wellbore via a "macaroni string" (a narrow-diameter tubing reaching to the perforations); injection into a gas lift system; [69] and slow dissolution of an insoluble inhibitor placed in the rat hole. [70][71] These delivery methods are straightforward to implement but not necessarily without problems. For example, gas injection requires the inhibitor solution to be atomized properly and not to deposit subsequently on the tubular walls immediately adjacent to the injection point; [72] narrow tubing can plug.

The most frequently used method of delivering the inhibiting solution to the scaling brine has been the "inhibitor squeeze." Here an inhibitor-containing solution is forced into the formation, whereby the inhibitor then resides on the rock surface, slowly leaching back into the produced-water phase at or above the critical concentration needed to prevent scaling [the minimum inhibitor concentration (MIC)]. It is intended that the released inhibitor protect the tubulars, as well as the near wellbore. It is required, obviously, that the inhibitor adsorb on the formation rock with sufficient capacity to provide "long-term" protection. It is also required that the inhibitor be relatively stable to thermal degradation under downhole conditions and be compatible in the particular brine system. And it is also required that the inhibitor treatment not cause a significant permeability reduction and reduced production (see discussion that follows). These requirements are generally achievable, but again, one chemical does not necessarily fit all field situations. [73]

Two types of inhibitor squeeze treatments are routinely carried out where the intention is either to adsorb the inhibitor onto the rock by a physico-chemical process —an "adsorption squeeze"—or to precipitate (or phase separate) the inhibitor within the formation pore space onto the rock surfaces—a "precipitation squeeze."

Adsorption of inhibitors is thought to occur through electrostatic and van der Waals interactions between the inhibitor and formation minerals. The interaction may be described by an adsorption isotherm, which is a function of pH, temperature, and mineral substrate and involves cations such as Ca+2. The adsorption process for retaining inhibitor in the formation is most effective in sandstone formations. Treatment lifetimes are generally on the order of 3 to 6 months.

The "precipitation squeeze" process is based on the formation of an insoluble inhibitor/calcium salt. This is carried out by adjusting the calcium ion concentration, pH, and temperature of polymeric and phosphonate inhibitor solutions. Also used are calcium salts of phosphino-polycarboxylic acid or a polyacrylic acid scale inhibitor. The intent is to place more of the inhibitor per squeeze, extending the treatment lifetime. Normally, the precipitation squeeze treatment lifetime exceeds one year, even when high water production rates are encountered.

The engineering design of such adsorption and precipitation squeeze treatments into real-world multilayer formations is generally done with an appropriate piece of software. This simulator takes core flood data and computes the proper pre-flushes, inhibitor volumes, post flushes, and potential squeeze lifetime. Computer simulation of such chemistry is described in Shuler[74] and Yuan et al.[75]

The sequence of pumping steps involved in squeezing inhibitors is listed next.
  • Acid cleans the scale and debris out of the wellbore to "pickle" the tubing (this fluid should not be pushed into the formation).
  • A "spearhead" package (a demulsifier and/or a surfactant) increases the water wetness of the formation and/or improves injectivity.
  • A dilute inhibitor preflush pushes the spearhead into the formation and, in some cases, cools the near-wellbore region.
  • The main scale-inhibitor treatment, which contains the inhibitor chemical, is normally in the concentration range of 2.5 to 20%.
  • A brine overflush pushes the main treatment to the desired depth in the formation away from the wellbore.
  • A shut-in or soak period (usually approximately 6 to 24 hours)—the pumping stops and the inhibitor adsorbs (phosphonate/polymers) or precipitates (polymers) onto the rock substrate.
  • The well is brought back to production.


Fig. 9.21 illustrates a typical inhibitor return curve that shows the concentration of an inhibitor dissolved in the water phase as the well is brought back on production.


A large amount of inhibitor returns immediately after turning on the well. This is nonadsorbed inhibitor or weakly adsorbed inhibitor. It is "wasted" in the sense that it is not available for use late in the life of the squeeze. This wasted inhibitor does not otherwise impose a serious financial burden on the treatment—the inhibitors can be the cheapest part of the inhibition treatment. The plateau (or slowly declining) portion of the return curve is the critical data that describe the effectiveness of the treatment. As long as the curve is above the MIC, scale deposition is not taking place in the formation or wellbore. Immediately below the MIC, scale formation may start to occur.

The x-axis in Fig. 9.21 is given in terms of time (months). The lifetime parameter is more correctly volumes of water produced. Obviously, a high rate of water passing over a given amount of inhibitor will maintain the MIC for a shorter period of time than a low rate of water passing over the same amount of inhibitor.

Scale-inhibitor squeeze treatments can sometimes bring undesirable side effects. These side effects include: process upsets, poor process and discharged water quality on initial flowback, extended cleanup period, deferred oil, and the potential for a permanent decrease in oil production combined with an increase in water production. The first three side effects listed are functions primarily of the oil, brine, and squeeze chemicals. Most of these problems can by avoided or at least minimized by prior laboratory testing. Deferred oil is an intrinsic problem in well intervention. The improved production must pay for the deferred oil.

Permanent decreases in production after inhibitor squeeze treatments are usually associated with pumping large amounts of water-based chemicals into water-sensitive zones, assuming an otherwise proper treatment design and the use of clean fluids. Clay swelling and in-situ emulsions are damage mechanisms; low pH-inhibitor solutions are often detrimental to clays, in particular to chlorites. [76] Handling the scale inhibition of water-sensitive reservoirs is not a solved problem. Several routes are being investigated. One solution is the use of oil-soluble inhibitors. [77] Another is the use of water-in-oil emulsion ("invert emulsions"), similar to the invert emulsions used for time-delayed acidization. A third solution is the use of a mutual solvent preflush. [78] Here, the mutual solvent is the first chemical seen by the sensitive formation, and it is the last seen as the well is put back on production. Also used are "clay stabilizers" in the preflush. [79] As of this writing, no single approach solves all problems.

New inhibitor chemistry is also being developed to handle the harsher scaling environments such as particularly high supersaturated barium sulfate solutions (saturation indices > 350). [80] A case in point is the barite scaling problem in the North Sea Miller field. [81] "Harsh" conditions also include HT/HP reservoirs with severe thermal stability requirements. [82][83]

Combined Treatments. Well intervention to place the scale inhibitor is particularly costly with high-volume wells because of large amounts of deferred oil; intervention at remote locations (e.g., offshore platforms and subsea completions) adds to the cost. It is often possible to place a scale inhibitor as part of the scale-removal step, providing both treatments with one setup and intervention. One of these techniques is the inclusion of a scale inhibitor with the acid stimulation process for dissolving calcite scale. [84] The advantages are in cost and in putting the inhibitor into exactly the same zone opened up by the acid treatment.

A second dual-treatment technique consists of placing a scale inhibitor along with a hydraulic fracture stimulation. Inhibitors can be injected into the pumped gel/sand mixture with calcium ion to form a sufficiently insoluble and immobile scale-inhibitor material within the proppant pack. DTPMP acid (Fig. 9.20) has been used, as well as polyphosphates. [85][86] Other inhibitor formulations can generate a "glaze" on the proppant pack.[65] The concept has been effective with calcite and barite scales. This technology has been practiced since the early 1990s on the Alaskan North Slope and, more recently, in west Texas; lifetimes of nominally two years are now claimed.[85][65] Shown in Fig. 9.22 are return curves for such a treatment together with a return curve for a conventional squeeze. Here, lifetime is expressed in terms of quantity of water protected from scaling. There are also a few important ancillary advantages to the method greater than extended lifetime—the well returns to production faster because adsorption time shut-in is not required, and there is little opportunity for changes in the formation wettability and its attendant problems. The concept is illustrated schematically in Fig. 9.23.


A newer dual-treatment technique consists of deploying an inhibitor impregnated into porous ceramic proppant along with conventional proppant in hydraulic fracture stimulation.[87] Upon production, any water flowing over the surface of the impregnated proppant will cause dissolution of the scale inhibitor. Dry oil will not release the inhibitor from the beads or the insoluble inhibitor. Field examples of this technology are given in a couple of sources.[88][89] The advantages are similar to those of the nonencapsulated inhibitor/frac concept already discussed but with a potentially longer lifetime (e.g., 4 years). This comes at an additional cost that must be offset by savings in deferred oil and setup/intervention costs. [88] The targets are high-volume wells in remote locations, such as the North Sea and deep Gulf of Mexico. Both inhibitor/proppant techniques also protect the fracture itself from plugging with scale. This scaling occurs primarily when incompatible waters mix near the wellbore.

Corrosion

Corrosion control in oil/gas production is reviewed in depth in multiple sources,[90][91][92] from which some of the following material is abstracted.

Corrosion Chemistry of Steels. Iron is inherently (thermodynamically) sufficiently active to react spontaneously with water (corrosion), generating soluble iron ions and hydrogen gas. The utility of iron alloys depends on minimizing the corrosion rate. Corrosion of steel is an "electrochemical process," involving the transfer of electrons from iron atoms in the metal to hydrogen ions or oxygen in water. The corrosion reaction of iron with acid is described by the equation

RTENOTITLE....................(9.1)

This reaction is made up of two individual processes, which are

RTENOTITLE....................(9.2)

[the generation of soluble iron and electrons (this is the "anodic" process—the oxidation of the metal)] and

RTENOTITLE....................(9.3)

[the consumption of the electrons by acid to generate hydrogen gas (this is a "cathodic" process—the reduction of protons)].

This separation of the overall corrosion process into two reactions is not an electrochemical nuance; these processes generally do take place at separate locations on the same piece of metal. This separation requires the presence of a medium to complete the electrical circuit between anode (site of iron dissolution) and cathode (site for corrodant reduction). Electrons travel in the metal phase, but the ions involved in the corrosion process cannot. Ions require the presence of water; hence, corrosion requires the presence of water. This overall process is shown schematically in Fig. 9.24. [92] The space between the anode and cathode may be small or large depending on a number of factors.


Acid is not the only corrodant possible. Another common cathodic process is the reduction of oxygen, which is written as

RTENOTITLE....................(9.4)

This reaction can also take place at a location different from that of iron dissolution.

The other chemical constituents in the vicinity of the anodic sites determine the ultimate chemical fate of the Fe++ ion, such as the precipitation of iron-containing solids on or near the corroding surface.

The net rate of corrosion is determined by how fast the corrodant arrives at the iron-atom/water interface, how much corrodant is present, the electrical potential (energy) of the corrodant (oxygen has a higher potential than do protons), and the intrinsic rate of the cathodic reactions—electron transfer processes involving protons and oxygen are not instantaneous and depend on the nature of the solid surface on which they occur.

"How fast the corrodants arrive" has two aspects: mass transport in the corroding fluid and permeating surface barriers between the iron metal and the water phase. Surface barriers are placed barriers, such as paint or plastic coatings, passivating oxide films inherent to the metal (discussed later), and low-permeability corrosion products (e.g., siderite, as formed in the presence of certain oils and/or inhibitors).

The Nature of Steels. Alloying iron with carbon (usually 0.2 to 1%) forms steel (low-alloy steel)—a far stronger metal than iron, hence, suitable for oilfield use. Other components can be added to iron to enhance corrosion-resistance properties.

Some of the carbon added is insoluble, forming iron carbide (Fe 3 C), which accelerates the cathodic processes necessary for corrosion to take place, accelerating the corrosion rate. One of the major, ubiquitous impurities in steel is sulfur, and it is a major source of corrosion instability. This element is highly insoluble in iron and precipitates in the form of insoluble sulfide inclusions, in particular MnS and (Mn, Fe)S. These inclusions are generally the sites of pitting (discussed later). [93]

Grain boundaries are also areas that are chemically active. [92] When iron solidifies during casting, the atoms, which are randomly distributed in the liquid state, arrange themselves in a crystalline array. This ordering usually begins simultaneously at many points in the liquid, and as these blocks of crystals and grains meet, there is a mismatch in the boundaries. There are areas of higher energy. Chemical impurities in the melt tend to accumulate at these grain boundaries and are more susceptible to chemical attack than the iron surface itself.

Plain carbon steels are processed by one of four heat treatments: annealing, normalizing, spherodizing, and quench and tempering. These treatments determine, in part, the physical and corrosion properties of the metal. Annealing or normalizing results in greater corrosion resistance than spherodizing or quench and tempering. The logic is that these treatments determine, in large, part of the physical dimensions and distribution of the impurities and inclusions in the metal.

The corrosion products formed in oxygen-containing water on mild steel are FeOOH, likely amorphous, and magnetite. [94] Below 200°C, these oxides, in the absence of reactive inclusions, are protective. In the presence of dissolved CO2, FeCO3 films form, which can sometimes be protecting (discussed later).

The compositions of corrosion-resistant alloys (CRAs) are chosen to spontaneously generate surface oxide films that will be stable and impermeable in the presence of the more aggressive corrodants. In oilfield use, it is also required that these films spontaneously reform if ruptured, as, for example, during and after erosion by sand or scratching by wireline/caliper tools. CRAs include the ferrous stainless steels and nonferrous nickel and cobalt alloys. Stainless steels contain at least 12% chromium. These alloys passivate in oxidizing environments through the formation of a thin layer of chromium oxide—containing film on the surface of the alloy. The crystallinity of this film decreases with increasing Cr content in the steel, becoming more glass-like and more protective. [94] Again, various inclusions can be weak points in the passivating film. The surfaces of nickel-based CRAs, such as Incoloy 800™, are a passivating nickel ferrite (Ni0.8 Fe2.2 O4).

There are four classes of stainless steels that are based on chemical content, metallurgical structure, and mechanical properties. These classes are martensitic, ferritic, austenitic, and duplex. The manufacturing processes for CRAs are more complex than those producing low-alloy steels. Stainless steels are less costly than the nickel and cobalt alloys, though they are 1.5 to 20 times more expensive than low-alloy steels.

Oilfield Corrosion. Oilfield corrosion can be divided into categories.

Corrosion because of oxygen is found with surface equipment and can be found downhole with the oxygen introduced by waterflooding, pressure maintenance, gas lifting, or completion and/or workover fluids. It is the major corrodant of offshore platforms, at and below the tide line. The chemistry of this process follows the equations previously given.

"Sweet" corrosion is generally characterized first by simple metal dissolution followed by pitting. The corrodant is H+, derived from carbonic acid (H2CO3) and the dissolution of CO2 in the produced brine. The pitting leaves distinctive patterns (e.g., "mesa" corrosion), attributable to the metallurgical processing used in manufacturing the tubing. "Ringworm" corrosion is caused when welding is not followed by full-length normalizing of the tubular after processing. Corrosion inhibitors and CRAs are effective in mitigating sweet corrosion. Naphthenic acids and simple organic acids indigenous to crude oil also contribute to corrosion.

"Sour" corrosion (H2S) results in the formation of various insoluble iron sulfides on the metal surface. Not only is H2S an acidic corrodant, it also acts as a catalyst for both the anodic and cathodic halves of the corrosion reaction. Galvanic corrosion (bimetallic corrosion) is caused by the coupling of a corrosive and noncorrosive metal in the presence of a corrodant. Erosion is yet another category of corrosion. Erosion corrosion is the acceleration of corrosion because of the abrasion of metal surfaces by particulates (e.g., sand). Finally, there is corrosion caused by acids—those used to stimulate wells (HCl and HF).

Oilfield corrosion can take specific forms: metal wastage, pitting, crevice corrosion, intergranular corrosion, stress corrosion cracking (SCC), blistering, embrittlement, sulfide stress cracking (SSC), and corrosion fatigue. The first five forms involve primarily carbonic acid and/or dissolved oxygen as corrodants. Items 6 through 8 are induced primarily by H2S.

Corrosive failure by uniform loss of metal is only infrequently seen during the production of oil and gas. It is, however, the first step in corrosive failure of steels by means of localized corrosion. A circumstance for severe metal wastage is the pumping of poorly inhibited matrix stimulation acids.

Pitting is the common failure mode of sweet corrosion and corrosion because of dissolved oxygen. All passivating/protecting films on steel contain weak spots that will preferentially dissolve and form pits. As mentioned, these areas are generally the sulfide inclusions. Chloride ion weakens the repassivating film, allowing continued dissolution. The decreasing pH within the pit also enhances continued corrosion. The driver for theses processes is the large cathodic area of the metal oxide surface vs. the small anodic pit. Pitting is particularly dangerous because penetration through a tubular can occur relatively fast. Other corrosion mechanisms, such as SCC, frequently start at pits. Oxygen scavengers are typically used to remove this gas in an attempt to minimize the pitting problem. However, small amounts may remain (e.g., 20 ppb), and these can be sufficient to induce corrosion.

Carbonic acid, the driver for sweet corrosion, is a weak acid. The pH of the formation water depends on the CO2 partial pressure, temperature, and alkalinity (controlled primarily, but not exclusively, by the presence or absence of carbonate minerals in the formation). Shown in Fig. 9.25, as a function of CO2 partial pressure, are computed pH values for a seawater brine (containing 140 ppm alkalinity) and a seawater brine saturated in calcite at 50 and 150°C (substantially higher alkalinities). For the common case of carbonate-containing reservoirs and moderate temperatures, produced waters should have pH values of 6 or greater. Waters exposed to greater amounts of CO2 in noncarbonate-containing reservoirs can have pH values of 4 or less.


Such corrosion induced by CO2 is a function not only of CO2 partial pressure and temperature but also of the crude oil. Crude oil contains surface-active chemicals—some oils contain more than others. These chemicals (e.g., resins and asphaltenes) can impact the corrosion process, at least for low-alloy steels. For a fixed brine composition, WOR, temperature, and pressure, corrosion in the presence of some crudes can be negligible, while in the presence of others, it can be extreme under identical environmental conditions. [95][96] Sweet corrosion generally results in the deposition of insoluble FeCO3 (siderite) on the steel surface. It has been suggested that this selectivity to oil composition relates to the physical morphology of the FeCO3 corrosion product—a compact, tight film can protect the steel; a loose, poorly adherent film does not. [96] An example is shown in Fig. 9.26. The average uniform corrosion rate for steel in Crude B was 0.6 mil/yr; the corrosion rate in Crude E was 26 mil/yr. Many corrosion inhibitors apparently act by the same mechanism (i.e., the generation of siderite films similar, and/or more compact than those formed from Crude B). [96]


Alternatively, it has been suggested that wettability plays the dominant role, whereby the surface-active components in the crude oil provide for a water-wet surface (high corrosion rates) or an oil-wet surface (low corrosion rates). [97] Regardless of the mechanism, crude oil can modify the corrosion rate. The penalty for ignoring the effect of crude-oil chemistry is the cost of overtreating or using more expensive alloys than are required.

A crevice, such as the junction space under a bolt or the physical junction of two metal parts, is in effect a pit. Uniform corrosion can initiate (in the presence of a corrodant) within the crevice and continue, driven by the large cathodic area outside the pit or crevice.

Stress corrosion cracking is intergranular corrosion, but it takes place only when the metal is under stress and in the presence of a corrodant. The corrodant can be specific—not all corrodants induce SCC on all alloys. Metal wastage is generally small; SCC is often preceded by pitting. High-strength steels are more susceptible to SCC than low-strength alloys. The severity of intergranular corrosion generally depends on the metallurgical history of the steel. Austenitic steels (common stainless steels) are particularly susceptible to intergranular attack.

Blistering, as well as embrittlement and sulfide stress cracking, a subclass of SCC, all stem from the same cause: the presence of H2S in the system and at the metal surface. The roots of the problem are in the mechanism for the cathodic discharge of hydrogen. The mechanism already discussed for the cathodic portion of the acid-induced corrosion process itself, involves two steps.

RTENOTITLE....................(9.5)

and

RTENOTITLE....................(9.6)

(i.e., the proton is first reduced to a hydrogen atom on the metal surface (H), followed by the combination of two hydrogen atoms to yield hydrogen gas). Hydrogen sulfide inhibits the combination of hydrogen atoms (as does arsenic and some other corrosion inhibitors). Accordingly, the hydrogen atoms can penetrate into the metal where they cause the corrosion problems that were already listed. This is shown schematically in Fig. 9.27. [91]


This hydrogen entry into low-strength steels can result in hydrogen blisters, if there is a macroscopic defect in the steel such as an inclusion. Such a void can provide a space for the hydrogen atoms to form hydrogen gas. Pressure builds and blisters form resulting in rupture and leakage.

Embrittlement (hydrogen-induced cracking and hydrogen embrittlement cracking) causes failure at stresses well below the yield strength. This phenomenon usually occurs only with high-strength, hard steels, generally those having yield strengths of 90,000 psi or higher. Tubing and line pipe (electric welded and seamless) are susceptible to this effect. The dominating factor is the metallurgical structure of the steel relating to its method of manufacture.

SSC cracking failure requires only low concentrations of H2S. The time to failure decreases as stress increases. Cracking tendency increases as pH decreases. SSC can be thought of in the same language as that used in describing hydraulic fracturing. There is a critical "stress intensity factor" below that at which a fracture (crack) will not propagate. This factor is related linearly to tensile strength. Some of this problem has been attributed to the effects of cold working on the alloys. Alloys that were stress relieved were found to increase in resistance to SSC. [98]

Wells producing hydrocarbon liquids, with the hydrogen sulfide, are less susceptible to SSC, pitting, and weight loss. For example, certain Canadian condensate wells have produced fluids with 40 mol% H2S and 10% CO2 for 30 years without serious corrosion problems. Stability is associated with a protective iron sulfide film, wetted by the oil/liquid hydrocarbon. These wells also had a BHT of 90°C; iron sulfide films are less effective in preventing corrosion above 110°C.

Steels, repeatedly stressed in a cyclical manner, may fail in time (corrosion fatigue). It is required for failure that the stress be above a critical value called the "endurance limit" (nominally 40 to 60% less than the tensile strength). The presence of a corrodant substantially reduces the fatigue life of a metal. Cyclic stress can be looked upon as a method of accelerating failure because of the other mechanisms previously described.

Bimetallic corrosion/galvanic corrosion can occur when two metals are coupled (in electrical contact) and a corrodant is present. The more reactive metal corrodes faster, while the less-reactive metal shows little or no corrosion. The more-reactive metal cathodically protects the less-reactive metal (exploiting cathodic protection to prevent corrosion is discussed later). In general, the total corrosion of the anodic material is proportional to the exposed area of the cathodic material. Thus, steel rivets in monel corrode very rapidly, while monel rivets in steel cause little damage.

Weld-related corrosion is a variant of galvanic corrosion. When a metal is welded, the welding process can generate a microstructure different from that of the parent metal. As a result, the weld may be anodic vs. the parent metal and may corrode more rapidly. This corrosion may take the form of localized metal wastage; if H2S is present, there is SSC cracking of hard zones in the metal or in the heat-affected zone. Similar problems can arise with electric-resistance-welded pipe.

Metal wastage in sweet systems is avoided by using weld consumable with a higher alloy content than that of the base metal; recourse is made to laboratory measurements to achieve the proper weld-metal/base-metal combination. Welding procedure standards are available to avoid hard zone SSC. Chemical inhibition is also effective in protecting welded pipe.

Coping With Corrosion. The paths to obviating corrosion problems are conceptually straightforward: isolate the metal from the corrodant; employ a metal alloy that is inherently resistant to corrosion in the corrosive medium; chemically inhibit the corrosion process; move the electrical potential of the metal into a region where the corrosion rate is infinitesimally small ("cathodic protection"); or live with the corrosion and replace the corroded component after failure.

Isolation is the regime of paints, coatings, and liners. An introduction to the subject is given in "Corrosion Control in Petroleum Production,"[92] from which some of the following discussion is abstracted; a detailed discussion of these subjects is in "Coatings and Linings for Immersion Service,"[99]. For any coating to be effective, it must be sufficiently thick to completely isolate the item being protected from the environment. Small holes in the coating ("holidays") result in the rapid formation of pits. Considerable care and quality control is required to guarantee the generation of holidays during service.

Organic coatings, such as asphalt enamel and coal tar enamel, are used to protect equipment concerned with the handling of oil and gas. Baked thin-film coatings, such as thermosetting phenolics and epoxies (applied in multiple coats), can be used to protect tubular goods. External protection of pipelines frequently involves use of adhesive tapes made of polyethylene or similar materials. Fusion bonded epoxy has been used successfully to protect a 150-km seawater-injection line (oxygen was the corrodant, much of which, but not all, was removed by scavenging chemicals). [100]

Inorganic coatings include both sacrificial coatings, which furnish cathodic protection (see below for mechanism) at small breaks in the coating, and nonsacrificial coatings, which protect only the substrates actually coated. Sacrificial coatings include galvanizing or coating with other metals anodic to the substrate and heavy suspensions of anodic metals (e.g., zinc particles, in silicates or organic vehicles). Zinc-silicate coatings (paints) are often used to coat the splash zone of drilling and production platforms. The zinc metal provides for cathodic protection of the steel substrate. Below the water line, the most economical approach to corrosion control is cathodic protection (see below). The pH of the environment is important— highly basic or acidic environments can remove coatings.

Nonsacrificial inorganic coatings include metal platings such as nickel and nonmetallic coatings such as ceramics. Nickel can be applied by electroplating or electroless plating. Ceramic coatings, when properly applied, are highly effective; they are also costly and fragile. Other systems, while not truly coatings, perform the same function (e.g., Portland cement and plastic liners). Plastic liners have been used for internal protection of tubing and lined pipe. Some liners are sealed into individual joints of pipe and tubing; some are fused into one continuous close-fitting liner through the entire pipe. Both cement and plastic liners are suitable for water lines.

The proper application of coatings is, in large part, an art form. Accordingly, it is also not possible to overemphasize the need for close inspection of the coating process, good quality control, and testing that the coating has been complete.

From a cost point of view, low-alloy steels are preferred. In certain cases, "minor" alterations in alloy composition can minimize corrosion. For example, L-80 steel with a tempered martensitic structure and a chromium content > 0.5% has been used without problems in 20-ppb oxygen-containing environments, while a similar steel with < 0.1% Cr has shown serious corrosion. [101]

The choice of using CRAs or chemical means to solve the more severe corrosion problem comes down to economics (available capital vs. long-term operating costs). Remoteness of operation becomes an important consideration in determining operating costs, as does downtime and deferred/lost oil because of repeated intervention for inhibitor application. Availability and cost of platform space is a consideration for offshore facilities.

The corrosion-control effectiveness of CRAs depends on the chemical severity of the environment. Crevice corrosion, pitting attack, and SCC are the primary concerns. The corrosion resistance of annealed austenitic stainless steels, such as 304 and 316, is affected by the presence of chlorides and temperature; type 304 is less corrosion resistant than type 316. Both materials are susceptible to SCC when the temperature is above 150°F. Both alloys are also low-strength steels. Alloys 654 SMo and AL6XN can be manufactured to higher strengths and are more resistant to SCC. Austenitic stainless steels are probably the most susceptible of all ferrous alloys to pitting.

Martensitic stainless steels have had the widest range of use of any of the available CRAs. Such steels may be manufactured through heat treatment into tubular products with acceptable yield strengths for downhole tubing. Many millions of feet of tubing type (grade L-80) 13Cr are in corrosive well service; it is considered the material of choice for deep sweet-gas wells with temperatures less than 150°C. About 35% of the L-80 13Cr usage was for oil wells. The passivity of 13Cr is destroyed by high chloride levels, particularly at high temperature, which can lead to pitting and crevice corrosion.

Duplex stainless steels are high-strength alloys achieved by means of cold working. Such steels are more corrosion resistant than martensitic steels but are similar in resistance to SSC. Cold-worked duplex has been used to 0.3 psi H2S. Annealed duplex is more resistant to H2S and SSC than the cold-worked versions. Annealed duplex line pipe has been used in wet CO2 service (99%) without problems. 22Cr duplex steel has been used where pH2S was between 0.5 and 1 psi. Such steels have been used successfully in HT/HP wells (e.g., 350°F and 14,000 psi), producing no H2S. However the copresence of chloride, stress, and dissolved oxygen can induce SSC. Wells not exposed to even small amounts of oxygen have operated successfully. [102]

The material most commonly used for sour service is AISI Type 4130 steel, modified by microalloy additions with a quenched and tempered microstructure (martensite).[103] C-110 steel has been used as casing in North Sea wells (30 to 60 bar CO2 and 30 to 50 millibar H2S). [104] An overview of CRAs and their use in sour service is given in Treseder and Tuttle.[90]

Nickel and cobalt alloys are used in the most severely corrosive conditions (high pressure, high temperature, and high H2S contents). C-276, a nickel-based alloy, can be used to 8,000 psi H2S and 400°F. Nickel alloys have found extensive use in the Mobile Bay fields. They are less expensive than the cobalt alloy MP35N previously used for such extreme conditions. Nickel alloys are also used as weld cladding for wellhead and valve equipment.

As with scale problems, the appropriate addition of chemicals can often inhibit corrosion problems, including some effects of H2S. The delivery techniques are often the same, but the inhibition mechanisms and types of chemicals are different.

Neutralizing inhibitors reduce the hydrogen ion in the environment. Typically, they are amines, ammonia, and morpholine. They are effective in weak acid systems but are stoichiometric reactants: one molecule equivalent of inhibitor per molecule of acid. They have found minimal use in the oil field.

Scavenging inhibitors are compounds that also remove the corrodant. Oxygen scavengers are commonly used in the oil field (e.g., in removing oxygen during water injection).

The majority of the corrosion inhibitors employed during production form thin barrier layers between the steel surface and the corroding fluid. The concept is that the organic inhibitor will strongly adsorb on the metal wall to form a barrier, possibly only a few molecules thick, which will prevent access to the corrodant and possibly leave the surface oil-wet (further retarding access of the corrodant). The generic name given to these compounds is "filming amines." This name is qualitatively correct in that most inhibitors are indeed nitrogen-containing, and the inhibitor does finally reside on the surface. The specific mechanism can be more complicated. For example, the inhibitor can interact with the corrosion product to increase its adherence and to lower its permeability. Such layers are likely to be far thicker than a few molecules. [96]

Regardless of the specific mechanisms involved, the inhibitor must contact the metal substrate. The general procedures are tubing displacement; displacement from the annulus; continuous injection; squeeze into the reservoir as liquid or gas; weighed liquids/capsules/sticks; and vapor-phase inhibitors.

The first two batch treatments are operated by pushing the inhibitor-containing fluid across the face of the production tubulars top-down (Item 1) or bottom-up (Item 2). The inhibitor film then persists on the metal surface for some period of time ranging from days to months, depending on the specific environment and materials.

Continuous injection is done if the well completion allows for a "macaroni string" reaching to the perforations. This technique often includes a simple-to-complicated valving system; it is to be remembered that valves can plug. Injection through the annulus has also been used.

Inhibitor squeezing into the formation is an alternative. Here, the mechanism is different than that of scale inhibitor squeezes. The large amount of inhibitor that returns initially is not wasted but is intended to coat the tubular and production equipment with an adsorbed, persistent film of inhibitor. The small amounts of inhibitor that subsequently desorb from the formation are intended to repair holes that are generated in the initial film.

Weighed liquids/capsules/sticks are all variations on the theme of placing inhibitor in the rathole where it is slowly released into the wellbore fluid, continuously depositing and/or repairing the protective film.

Vapor-phase corrosion inhibitors are organic compounds that have a high vapor pressure, generating volatile corrosion inhibitors (such as some amines) that allow this inhibitor material to migrate to distant, and often otherwise inaccessible, metal surfaces within the container. Such inhibitors have been used on the Trans-Alaska pipeline to protect low-flow areas, dead legs, and the annular space in road casings and contingency equipment. The concept has also been applied to storage tank protection. [105]

Filming-amine inhibitors are intended to protect steels from the action of "natural" corrodants in the produced hydrocarbon and water phases. They are generally not effective in protecting the steels from the acids used to stimulate wells or from the partially spent acids returning from such treatments. These tasks are accomplished by the inclusion of large dosages of different inhibiting chemicals with the stimulation acids. Such inhibitor systems are also available to handle low-alloy steels and CRAs in HT/HP conditions. [106] Concern for stability of CRAs during matrix stimulation of deep hot wells has resulted in the use of organic acids such as acetic acid and formic acid rather than HCl. Inhibitor systems have been developed for these chemicals as well.

Cathodic Protection. This technology is used to protect pipelines, offshore platforms, and surface equipment and is discussed more fully in the Facilities and Construction Engineering section of this Handbook. As previously discussed, corrosion is an electrochemical process: iron atoms give up electrons; the electrons flow through the metal to the corrodant; ion movement in the water film contacting both corrodant and iron metal completes the electrical circuit. In certain important cases, it is possible to reverse this current flow out of the steel surface by the application of an external power supply (i.e., make the surface to be protected cathodic rather than anodic). The technology involved in employing cathodic protection must take into account the quantity of current required; composition and configuration of the impressed current anode; resistivity of the corroding medium; size of the item being protected; accessibility of the surface being protected; and length of the item being protected.

Nomenclature


Pr = reservoir pressure
Tr = reservoir temperature


Acknowledgements


The data for Fig. 9.5 are used with permission of Infochem Computer Services, London. Fig. 9.9 is used with permission of Études et Productions Schlumberger, Clamart, France. Figs. 9.12 through 9.19,9.21 through 9.24, and Fig. 9.27, copyright Schlumberger Oilfield Review, are used with permission. Fig. 9.26 is courtesy of the Electrochemical Society.

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SI Metric Conversion Factors


Å × 1.0* E – 10 = m
°API 141.5/(131.5 + °API) = g/cm3
bbl × 1.589 873 E – 01 = m3
bar × 1.0* E + 05 = Pa
ft × 3.048* E – 01 = m
°F (°F – 32)/1.8) = °C
gal × 3.785 412 E – 03 = m3
psi × 6.894 757 E + 00 = kPa


*

Conversion factor is exact.